Know-how about things mechanical is a part of our national character. The knack of making complicated machinery work is an American tradition. Good old "Yankee Ingenuity" applied to machines has produced countless achievements from the steamboat of yesteryear to Apollo 17 of today. Equally outstanding but not so well known examples of this native ability of ours are the stationary gas engines and reciprocating compressors found in the oil and gas industry. These machines, in various forms, have been around for well over 50 years and it is not at all uncommon to find 30-year-old installations still operating at full capacity, day in and day out. They range from small units of a few horsepower to giants of several thousand horsepower. These machines have served the oil and gas industry exceptionally well for a long time under extreme service conditions. Their durability and efficient performance certainly are a tribute to their designers and builders, and to the people who have operated and maintained them through the years. The purpose of this paper is to take a critical look at the "current state of the art" concerning the operation and maintenance of these machines and to comment in general on the subject of preventive maintenance in an effort to put some of the many aspects in proper perspective. The topic is far too broad and complex to cover in specific terms and each individual installation has many unique features that require special consideration. Therefore, this review will only attempt to point out certain guidelines and critical requirements that in the writer's opinion a sound preventive maintenance program should have. Then each location can be examined to determine if present methods have any deficiencies that should be changed.

This paper discusses the advanced planning required in wellhead design as a result of the many combinations of casings and tubings utilized in multiple completions.

The World War II Allied assault on the beaches of Normandy is described by Corneluis Ryan in The Longest Day, a book in which the author provides a detailed record of one day in history. It would be a mistake, however, to think that the story of the Normandy Invasion is completely told by relating only events of that single day. Planning for June 6, 1944 began years before, and nothing that happened on that day was more important than the efforts spent in planning the operation. Not only a military operation, but any major undertaking demands a detailed, well thought-out plan to achieve success, especially when the undertaking involves safety of personnel, considerable financial investment, and coordinated efforts of many people. Drilling a well is just such an undertaking, and a plan for drilling the well provides the drilling manager, the person with ultimate responsibility at the wellsite, exactly what a battle plan gives an army general -- a orderly and detailed program for successful completion of his mission. This paper will discuss in detail each of the components of a drill plan. In the case of a drilling project, success is measured by reaching total depth without exposing personnel to unnecessary hazards, while reducing total drilling days, keeping non-drilling days at a minimum and controlling overall costs. Simply stated the benefits of effective planning are fourfold: * Safety * Economy * Evaluation * Formation Protection

Problems inherent in drilling horizontally make planning particularly critical in such projects. Reaction time for the ever-changing formation are much shorter than when drilling a conventional directional well. A medium radius horizontal well with build rates ranging from 15deg/100 ft to 30-deg/100 ft can go awry quickly. This paper discusses the specific information required to produce a detailed well plan that will help ensure a successful horizontal project, such as build rates, horizontal extensions, formation evaluation, drillstring components, pump restrictions and drilling fluid requirements. Several medium radius case histories are described briefly to illustrate the importance of planning.

The adverse effects of pulsations on compressor and pumping stations have long been recognized by industry if not totally understood. With the development of the SGA Compressor System Analog, a means is available to accurately predict piping pulsation levels and shaking forces and to optimize piping design from the standpoint of compressor efficiency. Experience has shown, however, that criteria based upon pulsation levels alone, or even upon pipe vibration levels, are inadequate for the design of reliable piping systems. To overcome such limitations, therefore, prediction techniques have been evolved to completely describe piping integrity in terms of vibratory stresses produced by the dynamic pulsation forces and static loading due to thermal expansion, pressurization, and bolt-up. These plant design techniques, used in conjunction with analog data, provide a broad spectrum of design capabilities from plant layout to detailed component design.

Plastic coatings have become a vital part of the Oil Industry for protection against corrosion in tubular goods, oil field storage tanks, and miscellaneous equipment. And for the protection against paraffin clogged flow lines and tubing. With oil field equipment being as expensive as it is and the need for the production of more oil ever present, it is easy to see the feasibility of a coating that will offer protection and prolong the life of this equipment twice it's normal life span. Giving complete satisfaction in performance.

Corrosion, as we speak of It, may be defined as an eating away of a material and it falls into two general categories: chemical attack, as in the action of an acid or oxygen on a metal, and electrochemical attack in which a chemical change takes place, dependent on the flow of an electrical current. This is also known as galvanic corrosion. Chemical corrosion results when a metal is placed in a reactive environment. This may be controlled by either changing the nature of the environment. This may be controlled by either changing the nature of the environment or insulating the metal from the environment. Usually in oil and gas corrosion we attempt the latter, either by use of inhibitors (chemical coating agents) or by the more permanent plastic coatings. In combating environmental attack, the insulating material must be completely inert to the environment and incapable of being permeated by that environment.

Many forms of artificial lift have been designed to deliquify gas wells. Plunger Lift is one form, utilizing the wells natural reservoir pressure as the prime energy source for removing the liquids from the bottom of the well bore. Intermittent operation of a motor valve installed on the tubing, allows fluid to be lifted to the surface, utilizing the free running plunger as an interface between liquids accumulated in the bottom of the well and the stored gas in the annulus. There are many variations of plunger lift employing multiple motor valves and many different sub-surface mechanical tubular arrangements. Chamber Lift is another form of artificial lift extending from Gas Lift. Combinations of Gas Lift and Plunger Lift have been used in the past and the technique described within is an extension of those methods.

Data acquired at various wells will be used to correlate the construction features of different types of plungers with their fall velocity. Some construction features cause a plunger to fall rapidly, while other features cause the plunger to have a slower fall velocity. Well conditions (gas flow rate and pressure) have a significant impact on plunger fall velocity. Published fall velocities can be used for each plunger type but may not be accurate for all wells, because fall velocity is impacted by many parameters. By accurately measuring the plunger fall velocity, the proper shut-in time for the plunger lift installation can be determined. The knowledge of how various parameters impact plunger fall velocity allows the operator to ensure that the plunger has reached the bottom of the tubing by the end of the shut-in period. Setting the well's controller to have the shortest possible shut-in time can maximize oil and gas production from the plunger lift well.

A new method for calculating plunger pump leakage in rod pumped wells is introduced. This method involves calculating a velocity profile for an annulus with the inner wall moving parallel to the outer wall. An average velocity is determined for the annular fluid flow, which in turn is used to calculate the fluid slippage. Eccentricity is also considered in the slippage calculation method. The results are evaluated against the historical field data and compare favorably to recent testing for smaller plunger clearances. Work remains to be done at larger clearances. A formula for calculating viscous plunger drag is also introduced.

Controlling plunger-lift wells has always proven tricky, if not outright difficult. The advent of electronic controls dramatically improved the success of plunger-lift applications. The reliability of controls along with the varied programs available has made the job easier, and therefore improved the overall operation. Wells never before considered candidates are now regularly employing plunger-lift. While the reliability and flexibility of equipment has improved, most plunger-lift wells are still operated at less than optimum levels of productivity. Today's busy well operators have less time available, making optimization difficult. Utilizing telemetry, along with the Auto-Cycle algorithm, has shown dramatic increases in production, eliminated down time, and maximized the pumper's time. It also serves to provide real time production and management data. This paper looks at several fields where operators have maximized their time, and increased their production through field automation.

The development of the Eumont gas play in Lea County, New Mexico created unacceptably high operating costs associated with gas well production. Two major issues were economically producing low pressure gas wells (1, 5-2 psi/l00 feet) with low connate water production and proppant production. The first choice for artificial lift once loadup occurred was beam pumps. Sand production and low fluid volumes however forced a paradigm shift to evaluate plunger lift as an alternative based on the low fluid volumes and low bottom hole pressures. The end result has reduced operating costs by over 70% in the areas that plunger lift has become the primary artificial lift method and reduced the lease expense per BOE by 25% over the 2-1/2 year implementation period. This paper discusses the steps taken to apply basic plunger lift concepts and progresses to the current plunger lift system that incorporates annular flow to minimize bottom hole pressure; therefore maximizing production. Evidence will be presented to validate that switching from beam pump to plunger lift has on average increased production. integrating this "new found" technology on high GLR oil wells has been beneficial as well.

A project was undertaken to utilize plunger lift in wells with abnormally low bottom hole pressures. This was accomplished through the use of coiled tubing for side-string injection (see schematic). This application has a wide range of applicability for high water cut low-pressure reservoirs.

It is the purpose of this paper to provide some assistance whether or not plunger lift is an economically viable alternative production method for specific wells. An evaluation spread sheet has been developed to assist in determining whether or not a rod pumped well is a likely candidate for plunger lift. The paper seeks to describe the assumptions and derivations of the equations in the spread sheet to provide a through understanding of the methods used in developing the spread sheet.

With the increase of horizontal drilling for oil and natural gas, the problem of keeping liquids removed from the wellbore becomes more evident. Several methods of artificial lift have been implemented to resolve this problem with varying results. This paper will discuss the use of plunger lift to resolve this problem and the mechanical requirements associated with plunger lift.

Plunger lift Technology has been with us for decades, no one knows for sure who first developed the idea, but we have seen the technology evolve from a rough guessing game to a near absolute science. The introduction of the electronic controller has brought the technology further than any other single development. This paper will cover one of the many areas, where electronics have allowed us to refine the technology

To unload liquid from a conventional plunger lift well requires that sufficient pressure builds during the shut-in time period as the plunger falls through gas, liquid and then rests at bottom on the bumper spring. Industry rule-of-thumb criteria to determine when the well should be opened to unload the liquid include building casing pressure, CP, to 1 _ times the line pressure, LP, or also using the tubing pressure, TP, in the Load Factor (CP-TP)/(CP-LP) calculation to be less than one-half(_). The best technique to predict the maximum casing build pressure may be to use the Foss and Gaul1 model to predict the rise velocity within a range of 500-1000 fpm, more optimally at 750 fpm that will unload plunger and liquid to the surface. These criteria are compared to one another and several well examples are analyzed using all three methods. Analysis of the results allow an operator to determine the shut-in casing pressure a plunger lift well should be allowed to build to before opening the valve to unload the liquid.

We could easily think of Plunger Lift as the ultimate in long stroke pumping. This is true because we have an expanding piston operating the full length of standard A. P. I. tubing without direct connection with surface mechanical energy. Rather than using the term "Pumping," we might think of Plunger Lift as a refinement of gas lift. plunger Lift operations are a form of intermitting gas lift, gas lift here referring to both natural flow and where additional gas is being injected, with the plunger constituting a seal between well liquids and propulsion gas. In performing this seal, the plunger minimizes the slippage, the fallback of liquids through the ascending gases, which is encountered when gas lifting low volume wells. The plunger is especially effective in deep wells with small production. It is in such wells that conservation of energy through the use of the plunger is most apparent. This, in most instances, permits a bigger degree of effectiveness and efficiency than has ever before been possible.

Plunger Lift operations are oftentimes not optimized due to lack of knowledge of plunger location and changes in tubing pressures, casing pressures and bottomhole pressures. Monitoring the plunger location in the tubing helps the operator (or controller) to optimize the production of liquid and gas from the well. In low liquid volume wells, the plunger position can be tracked from the surface by monitoring acoustic signals generated as the plunger falls down the tubing. When the plunger falls through a tubing collar recess, an acoustic pulse is generated. These acoustic pulses, generated at the tubing collar recesses, travel through the gas in the tubing and can be monitored at the surface to obtain plunger depth. These acoustic pulses are converted to an electrical signal by use of a microphone or pressure transducer. The signal is digitized, and the digitized data is stored and processed in a computer to determine plunger depth. In some high liquid volume wells, the acoustic pulses generated as the plunger falls past the tubing collar recesses may be masked and not detectable due to liquid accumulation around the plunger. However, in both low and high liquid volume wells, the plunger depth can be determined by generating an acoustic pulse in the tubing at the surface, and then, by monitoring the acoustic reflection from the top of the plunger. Multiple shots are taken, so the plunger descent rate can be determined throughout the plunger fall. Software processes this plunger depth data along with the tubing and casing pressure data to display plunger depth, plunger velocity and well pressures vs. time. Plunger arrival at the liquid level in the tubing, and plunger arrival at the bottom of the tubing are identified on the data plots. Well inflow performance is calculated and plotted. Software displays the data and analysis in several formats including a pictorial representation of the well showing the tubing and casing pressures, plunger location, gas and liquid flow rates in the tubing and annulus, and also, inflow performance relationship at operator selected intervals throughout the cycle. A field case is presented to show how this field data analysis is applied to optimization of Plunger Lift operations.

Fluctuating line pressures and liquid loading are a bad combination and in the Moxa Arch field in Southwestern Wyoming they presented the operator and Weatherford Artificial Lift Systems with a perplexing problem. Can conventional plunger lift be effective in an area with severe line pressure fluctuations? Can it provide for efficient removal of accumulated fluids while reducing or eliminating the need to vent the well and minimizing the time that the lease operator has to spend at the well location? Finally, can this be accomplished with limited resources of field personnel who are unfamiliar with the workings of plunger lift? This paper will discuss a 90 well plunger lift project in the Moxa Arch field that was successful in positively answering all these questions. It will describe the field history, the well candidate selection process, the initial pilot project and the total turnkey installation of plunger lift into 90 wells in a 3 month period of time. It will discuss the advantages of using an Integrated Solution Team approach to the project which provided for fixed installation costs and increased stabilized production, without placing additional burdens on the limited field personnel pool available.

The advent of "smart" microprocessor based plunger lift controllers has produces a renewed interest in the application of plunger lift to remove fluid from both oil and gas wells. While a great deal of information regarding the economics of plunger lift installations and operations exist there is little information available to assist in the design and evaluation of new plunger lift applications. This paper seeks to provide an approach to determining the operational feasibility of plunger lift operations in advance of equipment installation.

With today's economics in the oilfield, many operators are searching for ways to cut lift costs. Plunger lift is often considered. However, if it is projected that a particular well does not have sufficient gas to operate a plunger, this means of artificial lift is no longer considered. For instance, if a particular well shows to be 10 MCF per day below operating requirements, an operator may spend upwards of $50,000.00 to rod pump this well. An alternative would be to add 10 MCF per day to this well through gas injection. Many operators have high pressure gas available without realizing. Many have compression for gas sales, some have gas plants, and others have high pressure gas wells. All these examples are avenues that should be explored. This paper examines such scenarios in two West Texas fields.

After decades of trial and error, and frustration, plunger-lift finally has become widely accepted as a legitimate solution to producing many wells. As the experience level has increased, so has the success. As the equipment has been improved, so have the applications. This paper is to describe an application, coupled with new technology that is allowing producers to use plunger-lift systems on wells never before possible. The limiting factor for most plunger-lift wells is gas. It is now possible to take advantage of the low lifting costs of plungers on some of these wells.

As gas wells are produced and reservoir pressures decline, it is often necessary to install wellhead compression to maintain production. As the well continues to decline, gas rate and velocity in the tubing will decrease to the point where liquids cannot be lied out of the wellbore. Even on compression, liquid loading will become a problem and production impairments will result. One remedy to the problem of liquid loading is to install a plunger lift system coupled with compression. With new

Developed is an analytical analysis from which a synthesized dynamometer card can be calculated and plotted from generally known oil well parameters. The analysis preserves the time of displacement variable necessary for the calculation of instantaneous loads at any time or any position of the polished rod throughout the pumping cycle. The nonlinear boundary conditions introduced by the fluid pump are linearized and result In the applicability of superposition of loads in proper phase relationship. From the synthesized dynamometer cards various pumping conditions may be investigated; surface and subsurface equipment selected; and malfunction of system components determined.